MXPA02004535A

MXPA02004535A - Enhanced oil recovery.

Info

Publication number: MXPA02004535A
Application number: MXPA02004535A
Authority: MX
Inventors: Ramachandran Ramakrishnan
Original assignee: Boc Group Inc
Priority date: 2001-05-16
Filing date: 2002-05-07
Publication date: 2004-07-16
Also published as: AU4058402A; CA2384612A1; CN1385595A; US20030037928A1; EP1258595A3; EP1258595A2

Abstract

A method for enhancing the recovery of oil from underground formations is disclosed. A gas mixture which contains greater than 50% by volume carbon dioxide, the remainder typically being an inert gas, is injected in the underground formation to lower the oil viscosity and surface tension and increase the oil swelling. Preferably, the gas mixture contains greater than 60% by volume carbon dioxide with a gas mixture containing greater than 70% by volume carbon dioxide preferred.

Description

RECUPERATION RECEIVED OF IMPROVED OIL FIELD OF THE INVENTION The present invention provides a method for increasing the recovery of petroleum from underground formations. More particularly, the present invention provides means for injecting into the oil in the underground formation a gas mixture containing at least 50 volume% carbon dioxide and the rest nitrogen or other inert gas.

BACKGROUND OF THE INVENTION The oil or gas and any water that is contained in the porous rock surrounding the oil or gas in a tank or formation are typically under pressure due to the passage of the material above them. As such, they will move to an area of lower pressure and upper elevation such as the wellhead. After some pressure has been released, the oil can still flow to the surface but it does so more slowly. This movement can be helped by a mechanical pump such as the lifting pumps that they see frequently. These processes are typically referred to as primary oil recovery. Typically, less than 50% of the oil in the oil formation is recovered by primary techniques. The recovery can be increased following methods of increased oil recovery (EOR). Typically, these methods are divided into two groups: secondary and tertiary. Secondary EOR generally refers to pumping a fluid, either liquid or gas, towards the ground to accumulate pressure that dissipated during primary recovery. The most common of these methods is to inject water and is simply termed a flood with water. The tertiary recovery schemes typically use interactions or heat to reduce the viscosity of the oil so that the oil flows more freely or change the properties of the interface between the oil and the surrounding rock pores, so that oil can flow out of the oil. small pores in the rock and enter larger channels where the oil can be swept by a driving fluid or moved by pressure gradient to a production well. The oil can also be inflated so that a portion of the oil comes out of the small pores into the channels or larger pores in the rock. Steam injection, injection of miscible fluid and injection of surfactant are typical of these processes. Thermal techniques using steam can be used in a well-to-well scheme or in a single-well technique that is known as the blow-and-blow method. In this method, the steam is injected through a well in an amount sufficient to heat the underground formation containing hydrocarbon in the vicinity of the well. The well then closes during a soaking period after which it is put into production. After production has declined, the blow-and-blow method in the same well can be used again to stimulate production again. The use of carbon dioxide and its injection into oil deposits is known to increase production from well to well and from a single well. Carbon dioxide dissolves easily in the oil and causes the oil to swell and reduce the viscosity and surface tension of the oil which in turn leads to additional oil recovery. Carbon dioxide can also be used with steam so that steam and carbon dioxide are injected either simultaneously or in sequence, often followed by a soaking period, followed by an additional injection of carbon dioxide or other fluids. . E.U.A. 2,623,596 discloses enhanced recovery using gases in an injection well with recovery of oil from a separate production well. The increased recovery using C02 and N2 mixtures is discussed with data presented showing the recovery of oil that increases monotonically as percent of C02 in the gas mixture increases. Nevertheless, the presented data does not show the results when it is used between 85% of CO and 100% of C02. The Patent of E.U.A. 3,295,601 teaches that a gas stopper consisting of carbon dioxide and hydrocarbon gases, preferably two to four carbon atoms, or nitrogen, air, hydrogen sulfide, combustion gases and similar gases in a gas mixture, when are injected into a well, establishes a transition zone. This transition zone is then propelled through the injection well by a drive fluid that will produce oil from the stratum and reduce viscous pulsation. The preferred gas stopper consists of 50% carbon dioxide and a substantial concentration of C2 to C4 hydrocarbon gases such as 10 to 50% by volume. It seems that the rest of the gases in this gas mixture are selected from the group consisting of nitrogen, air, hydrogen sulfide and flue gases and similar gases that would form the remainder in the composition of carbon dioxide and hydrocarbon gas from C2 to C4, The US Patent 5,725,054 teaches a method for recovering oil from an underground formation by injecting into the well a gas mixture comprising carbon dioxide and a gas selected from the group consisting of methane, nitrogen and mixtures thereof. The gas mixture comprises about 5 to about 50% by volume of carbon dioxide. As noted in the examples, the highest percentages were 50% by volume of carbon dioxide. The present inventors have discovered that the use of carbon dioxide in percentages greater than 50%, up to 99%, together with nitrogen or other inert gas like the rest of the gas mixture will improve oil production.

SUMMARY OF THE INVENTION The present invention provides a method for increasing the recovery of petroleum from an underground formation comprising injecting into the oil a gas mixture comprising at least 50 vol.% Carbon dioxide and an inert gas. The present invention further provides a method for increasing the recovery of petroleum from an underground formation comprising injecting into the oil a mixture of gas comprising carbon dioxide and nitrogen, wherein the carbon dioxide is present in the gas mixture in a quantity of at least 50% by volume. In addition, the present invention will provide a method for reducing the viscosity and surface tension as well as increasing the volume or swelling of petroleum in an underground formation comprising injecting into the oil a gas mixture comprising at least 50% by volume of carbon dioxide. and an inert gas.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a graphical representation of the effect of gas carbon dioxide content on paraffin oil viscosity. Figure 2 is a graphical representation of the carbon dioxide content of gas in naphthene oil viscosity. Figure 3 is a graphical representation of the carbon dioxide content of gas in aromatic petroleum viscosity. Figure 4 is a graphical representation of the carbon dioxide content of gas in the paraffin oil surface tension. Figure 5 is a graphical representation of the gas carbon dioxide content in the surface tension of naphthene oil. Figure 6 is a graphical representation of the carbon dioxide content of gas in the surface tension of aromatic petroleum. Figure 7 is a graphical representation of the gas carbon dioxide content in the paraffin oil viscosity at various temperatures. Figure 8 is a graphical representation of the gas carbon dioxide content in the paraffin oil surface tension at various temperatures. Figure 9 is a graphical representation of the carbon dioxide content of gas in the volume of paraffin oil at various temperatures.

DETAILED DESCRIPTION OF THE INVENTION The present invention comprises a method for increasing the recovery of oil from an underground formation, comprising injecting into the oil a gas mixture comprising at least 50% by volume of carbon dioxide and an inert gas. The inert gas is preferably nitrogen. Other inert gases such as helium and argon can also be employed. The present invention also comprises a method for increasing the recovery of oil from an underground formation comprising injecting into the oil a mixture of gas comprising carbon dioxide and nitrogen. The carbon dioxide is present in the gas mixture in an amount of at least 50% by volume. The introduction of a combination of carbon dioxide and nitrogen gas into the formation provides an unexpected advantage of lower oil viscosity and lower surface tension than the introduction of carbon dioxide or nitrogen alone. This will also provide more oil swelling than the use of carbon dioxide or nitrogen alone. The use of nitrogen adds an economic advantage to the mixture since the cost is lower than that of pure carbon dioxide consumption. For purposes of the present invention, the applicants define petroleum as being a hydrocarbon comprising paraffin, aromatic or naphthene constituents or mixtures thereof. The mixture of carbon dioxide and nitrogen will be injected into the formation containing the oil at a pressure of 70.3 kilograms per square centimeter at 1,406 kilograms per square centimeter (100 pounds per square inch at 20,000 pounds per square inch) depending on the depth of the oil deposit. This method of injection allows the use of the well-to-well process WAG (alternating water with gas) whereby a gas injection is followed by a flood of water to boost oil and increase production at the well head. This injection method will also work in a process and blow and blow. In the process of blowing and puffing, the mixture would be injected into the formation. Then the formation would be sealed allowing a period of soaking for a prolonged period of time, followed by an improved oil recovery or production period. Mixtures of carbon dioxide and nitrogen can be created by any means. Preferably, a stream rich in carbon dioxide and a vapor rich in nitrogen are combined or a hydrocarbon is combusted using air or air enriched with oxygen to produce carbon dioxide. The present inventors assert that in addition to nitrogen, other inert gases, when combined with carbon dioxide in an optimum ratio, will minimize oil viscosity and surface tension while swelling is increased.

A means to produce the gas stream rich in carbon dioxide involves the use of a power plant or cogeneration plant at or near the well site. Air enriched with oxygen and hydrocarbon are combusted to generate energy and gas rich in carbon dioxide. The energy is used to operate an air separation plant that provides oxygen for the enrichment of oxygen from the power plant or cogeneration. The nitrogen and / or additional steam produced can also be used to increase oil recovery by placing these materials in an injection well either individually or in combination with the gas stream rich in carbon dioxide. The combination of heat and carbon dioxide can additionally improve the recovery and little carbon dioxide would be lost to the aqueous phase as a result. Another means of producing carbon dioxide is by injection of pure oxygen, air enriched with oxygen or air from the bottom of the well. For wells that are deep enough, the temperature will be sufficient to sustain combustion and produce carbon dioxide. For example, a well depth of 2,438.40 meters (8000 feet) can have a temperature of 149aC (300aF) that is hot enough to produce the carbon dioxide needed for increased oil recovery. In a preferred embodiment of the present invention, a mixture of dioxide of nitrogen and nitrogen with the present carbon dioxide greater than 50% by volume is injected into the formation in or near the production well by optimizing the composition of the gas mixture. Due to the varied regimes in the admission of carbon dioxide and nitrogen, an almost optimal composition in the formation at that injection location can be achieved. A second mixture of carbon dioxide and nitrogen would then be injected through the injection well (s) located at a distance from the production well. The composition of this gas mixture would be such that the viscosity and surface tension of the oil is higher than that of the oil near or in the production well but still reduced in comparison with the untreated oil. The gas can be fed continuously to the injection wells or the wells can be closed for a period of at least one day to facilitate the admission of the gas by the oil. Oil is driven into the production well and the pulsation or diversion of gas through oil is minimized as a result. In this preferred embodiment, more than one remote injection point can be employed so that the viscosity and surface tension of the oil at the remote injection point becomes higher with each injection point farther from the wellhead injection point optimizing the content of the gas mixture of carbon dioxide and nitrogen, consequently, the nitrogen content of the gas mixture will increase as the mixture is injected additionally from the well in production. This gradient will result in an elevation of the carbon dioxide content above 50% by volume as it is injected into points that in sequence are closer to the well in production. In this mode, a possibly intermittent subsequent use of carbon dioxide flooding, nitrogen flooding or water flooding to propel the oil into the production well could further improve yields. A preferred composition for use in the methods of the present invention is that of at least 50% by volume of carbon dioxide, the remainder being nitrogen or another inert gas including helium, argon or steam. In a more preferred embodiment, more than 60% carbon dioxide by volume with the remainder being inert gases would comprise the gas mixture. In the most preferred mode, more than 75% by volume of the gas mixture would be carbon dioxide and the rest being inert gases. In an additional mode, hydrocarbons can be added to the compositions described above, These hydrocarbons, such as methane, ethane and propane can come from traditional sources but can also come from the associated gas produced during oil production. The hydrocarbons can be separated from the oil and injected back into the ground or can be separated from the oil and injected back into the ground after burning a portion of the hydrocarbon in air, oxygen or air enriched with oxygen.

EXAMPLES Three model oils were studied to explore the potential of mixtures of carbon dioxide and nitrogen for enhanced oil recovery. A simulation was developed based on the Peng-Robinson equation of state for vapor-liquid equilibrium, the Twu model for liquid phase viscosity and a modified form of the Brock and Bird equation for surface tension. The three oils used in this study were paraffin type, naphthene and aromatic. A mixture of carbon dioxide gas and nitrogen with a rate of use of 1 mole per mole of oil was assumed and a small amount of water was added to the mixture since typically the carbon dioxide flood operations follow flooding procedures with water or are conducted as in the WAG method alternatively with flooding with water. the amount of water was based on 20% saturation for a typical oil. Pressures on the scale of 105.45 kg / cm2 absolute to 175.75 kg / cm2 absolute (1,500 to 2,500 pounds per square inch absolute) and temperatures on the scale of 242C to 93SC (75BF to 200aF) were studied. As shown in Figures 1, 2 and 3, and the Tables 1, 2 and 3, the ratio of a paraffin, naphthene and aromatic oil viscosity at 242C (759F) to the percentage of carbon dioxide in the oil recovery gas mixture is demonstrated. It can be seen that more than 50% of carbon dioxide in the gas mixture is advantageous in reducing the viscosity of petroleum in relation to the use of 100% carbon dioxide.

Table 1. Effect of C02 Content of Gas on the Viscosity of Paraffin Oil at Various Pressures and 249C (75eF).

Viscosity Viscosity Content of Gas Viscosity C02 Oil to Petroleum to Oil to (%) 105.45 kg / cm2 1 0.60 kg / cmz 175.75 kg / cm2 (1500 psia) (2000 psia) (2500 psia) 1: CP) ( CP) (cP) 0 0 592 0. 571 0 .552 25 0 .557 0, 534 0, 513 50 0. 515 0. 49 0, 468 68 0 .478 0, 453 0 .437 75 0, .462 0 443 0 .449 80 0 .45 0,, 451 0 .457 85 0,, 451 0. 46 0 .466 88 0 .456 0, 465 0 .472 92 0, 464 0. 472 0 .479 100 0, 478 0. 487 0 .493 Table 2. Effect of C02 Content of Gas on Viscosity of Naphthene Oil at Various Pressures and 24SC (75SF) Viscosity Viscosity Content of Viscosity Gas C02 Oil to Oil to Petroleum to (¾) 105.45 kg / cm2 140.60 kg / cm2 175.75 kg / c (1500 psia) (2000 psia) (2500 psia) (cP) (cP) (cP) 0 1.93 1.87 1.82 25 1.69 1.62 1.57 50 1.44 1.38 1.32 68 1.26 1.19 1.14 75 1.18 1.12 1.07 80 12 1.06 1.02 85 06 1.01 0.997 88 02 0.993 1.01 92 986 1.01 1.02 100 02 1.04 1.05 Table 3. Effect of C02 Content of Gas on Viscosity of Aromatic Petroleum at Various Pressures and 24aC (75QF) Viscosity Content of Viscosity of C02 Gas Oil to Petroleum to Petroleum at (%) 105.45 kg / cm2 140.60 kg / cm2 175.75 kg / cm2 (1500 psia) (2000 psia) (2500 psia) (cP) (CP) [CP) 0 0, 827 0.811 0 797 25 0.7566 0.738 0, 722 50 0.679 0.658 0 .642 68 0.615 0.595 0. 578 75 0.587 0.567 0.552 80 0.566 0.547 0..532 85 0.544 0.526 0.512 88 0.529 0.512 0..519 92 0.51 0.52 0..527 100 0.527 0.537 0.544 Figures 4, 5 and 6 and Tables 4, 5 and show the ratio of a paraffin, naphthene and aromatic oil surface tension to 24SC (75eF) to the percentage of carbon dioxide and the oil recovery gas mixture for three different pressures. As can be seen in Figures 4, 5 and 6, more than 60% carbon dioxide in the gas mixture is advantageous in reducing the surface tension compared to the use of pure carbon dioxide.

Table 4. Gas Content Effect of C02 on Surface Voltage of Paraffin Oil at Various Pressures and 24eC (752F) Super Tension Super Tension Super Tension Voltage of C02 ficial a ficial a ficial a: ¾) 105, 45 kg / cm2 140.60 kg / cm2 175.75 kg / cm2 (1500 psia) 2000 psia) (2500 psia) (dyne / cm) (dyne / cm; (dyne / cm) or 19 .22 18.39 17.65 25 17 .1 16.19 15.41 50 14 .93 13.99 13.21 68 13 .27 12, 35 11.8 75 12., 59 11.86 11.86 80 12 .09 11.91 11.9 85 11 .96 11.95 11.95 88 11 .98 11.98 11.98 92 12. 02 12.02 12.02 100 12 .09 12.1 12.1 Table 5. Gas Content Effect of C02 About Surface Tension of Naphthene Oil to Various Pressures and 242C (75aF) Content of Super Tension Super Tension Supergas of C02 ficial a ficial a ficial a (%) 105.45 kg / cm2 140 60 kg / cm2 175.75 kg / cm2 (1500 psia) (2000 psia) (2500 psia) (dyne / cm) (dyne / cm) (dyne / cm) 0 29 .21 28 .56 27.96 25 26 .14 25, .3 24.59 50 22 .93 21 .97 21.23 68 20 .4 19. 44 18.73 75 19 .34 18 .42 17.72 80 18 .53 17 .64 16.97 85 17 .69 16 .85 16.59 88 17., 16 16 61 16.62 92 16 .65 16 .66 16.66 100 16. 72 16, 73 16.73 Table 6. Gas Content Effect of C02 on Surface Tension of Aromatic Petroleum at Various Pressures and 24 ° C (75 ° F) Super Tension Super Tension Voltage Content Super gas of C02 ficial a ficial ficial a () 105.45 kg / cm2 140.60 kg / cm2 175.75 kg / cm2 (1500 psia) (2000 psia) (2500 psia) (dyne / cm) (dyne / cm) (dyne / cm) 0 29.84 29.29 28.79 25 26.71 25.96 25.33 50 23.41 22.53 21.87 68 20. 81 19. 94 19 .28 75 19 .73 18 .87 | 18 .25 80 18. 92 18 08 17 .48 85 18 .06 17 .28 16 .72 88 17 .52 16 77 16 .76 92 16 .8 16 8 16 .8 100 16. 86 16 86 16 .86 Figures 7 and 8 and Tables 7 and 8 show the ratio of a paraffin oil viscosity and surface tension at various temperatures to the percentage of carbon dioxide and the oil recovery gas mixture. As demonstrated in the above examples, more than 50% carbon dioxide in the gas mixture is advantageous compared to the use of pure carbon dioxide. The oil viscosity is greatly reduced to about 70 to 80% carbon dioxide while the surface tension remains approximately constant at higher concentrations of carbon dioxide.

Table 7. Gas Content Effect of C02 on Paraffin Oil Viscosity at Various Temperatures and 140.60 kg / cm2 absolute (2C00 psia) Content ViscosiViscosiViscosiViscosiViscoside C02 nity of Qodadity of P02 Petroleum Oil Petroleum Oil Petroleum 24aC at 38eC at 52BC at 66 ° C at 93SC (75SF) (1009F) (125aF) (150aF) (200SF) (CP) (cP) (cP) (cP) (cP) 0 0.571 0.486 0.419 0.365 0.282 50 0.49 0.429 0.375 0.329 0.257 75 0.443 0.387 0.341 0.301 0, 235 80 0.451 0.394 0.342 0.298 0.229 85 0.46 0.402 0.348 0.304 0.23 88 0.465 0.407 0.352 0.307 0.233 92 0.472 0.413 0.358 0.312 0.237 100 0.487 0.426 0.369 0.321 0.244 Table 8. Gas Content Effect of C02 on Surface Voltage of Paraffin Oil at Various Temperatures and 140.60 kg / cm2 absolute (2000 psia) Content Voltage Voltage Voltage Voltage Super-SuperSuperSuper- SuperC02 gas voltage Ficial ficial fiial fi cial (%) at 24aC to 38eC at 52QC at 66aC to 93aC (dyne / (dyne / (dyne / (dyne / (dyne / cm) cm) cm) cm) cm) 0 18 .39 17 .3 16.21 15.13 13 50 13 .99 12 .91 12.29 11.63 10.26 75 11 .86 10 .53 10.06 9,582 8,574 80 11 .91 10 .52 9,887 9,265 8,167 85 11 .95 10 .52 9,888 9,266 8, 044 88 11 .98 10 .52 9,887 9,266 8,046 92 12,02 10,52 9,888 9,266 8,044 100 12.1 10.52 9.887 9.265 8.045 Figure 8 and Table 9 show the relationship of a relative volume of paraffin oil at various temperatures in terms of the percentage of carbon dioxide in the oil recovery gas mixture. The relative volume is taken in comparison with a conventional oil volume. Approximately 70% to 99% of carbon dioxide in the gas mixture is advantageous compared to the use of pure carbon dioxide to maximize swelling in this case. As the swelling of the oil increases, the oil will leave the small pores within the underground formation and can be swept or boosted to the production well by using various flooding techniques.

Table 9. Effect of Gas Content of C02 in Relative Volume of Paraffin Oil at Various Temperatures and 140.60 kg / cm2 absolute * (2000 psia) a4u * v «-¾S-.r, Contents Volume Volume Volume Volume Gas volume of relatirelatirelati- relati- relati¬ C02 vo) of vo vc) of vc) of vo Oil Petroleum Oil Oil Petroleum (¾) to 24BC to 389C to 529C to 66SC to 93SC (75 ° F) (1002F) (125eF) (150ifF) (2002F) 0 1. 036 1 .053 1. 071 1. 090 1 .131 50 1. 118 1 .135 1. 154 1. 176 1 .235 75 1. 193 1 .222 1. 244 1. 27 1 .353 80 1. 188 1 .217 1. 249 1. 287 1 .392 85 1. 183 1 .211 1. 243 1. 280 1 .398 88 1. 179 1,207 1. 239 1. 276 1 .391 92 1. 175 1,203 1. 234 1. 271 1 .383 100 1. 167 1 .194 1. 224 1. 261 1 .366 * The relative volume is compared to a conventional oil volume. Although this invention has been described with respect to particular embodiments thereof, it is evident that numerous different forms and modifications of the invention will be apparent to those skilled in the art. The appended claims of this invention should generally be considered to cover all of these obvious forms and modifications that are within the true spirit and scope of the present invention.

Claims

1. A method for increasing the recovery of oil from an underground formation, which comprises injecting into the oil a gas mixture comprising at least 50% by volume of carbon dioxide.

2. The method according to claim 1, wherein the remainder of the gas mixture is selected from the group consisting of an inert gas, mixtures of inert gases selected from the group consisting of nitrogen, helium and argon; hydrocarbons, steam, air or mixtures thereof.

3. The method according to claim 1, wherein the gas mixture is injected into the oil at the wellhead.

4. - The method according to claim 1, wherein the gas mixture is injected to a single production wellhead.

5. - The method according to claim 4, wherein the injection is cyclic,

6. - The method according to claim 4, wherein the gas mixture is injected into an injection well other than the well head of production .

7. - The method according to claim 6, wherein the gas mixture is injected in an alternating pattern with a driving fluid.

8. - The method according to claim 7, wherein the driving fluid is selected from the group consisting of steam, water, nitrogen, carbon dioxide and air.

9. The method according to claim 1, wherein the gas mixture is injected into the oil at a pressure ranging from about 7.03 kg / cm2 to about 1,406.00 kg / cm2 (100 psi to about 20,000 psi).

10. - The method according to claim 1, wherein after injection of the gas mixture, the underground formation is sealed for at least one day. 11 - The method according to claim 10, wherein the sealed underground formation is opened and a flood of a material selected from the group consisting of carbon dioxide, nitrogen, water or brine is driven through the injection point . 12. The method according to claim 9, wherein the gas mixture is injected into the underground formation in at least two different injection points, where the percentage by volume of nitrogen in the mixture is higher in the second point of injection that at the first injection point and the first injection point is closer to at least one production well than the second injection point. 13. The method according to claim 1, wherein the gas mixture further reduces the viscosity and surface tension of the oil in the underground formation.